A feedwater heater is a particular type of heat exchanger which utilizes latent heat (as well as sensible heat) of a quantity of steam, used as a heating medium, to raise the temperature of feedwater passing therethrough. Such a heater is typically used in the environments of electric power generators, and more particularly in conjunction with steam boilers used therein. Thus, a train of feedwater heaters may be provided for a plurality of turbine stages with different heaters having different priorities in a hierarchy based on steam pressure and temperature. Of course, similar heaters, as well as the principles of this invention, may be used in other environments.
The structure of a typical closed feedwater heater may be of the type generally designated by reference numeral 10 in FIG. 1. As seen therein, a shell 12 includes an inlet 14 for a passageway for the steam, which may be obtained from various pressure stages of a power turbine. Feedwater enters the heater through an inlet 16. The heated feedwater exits the heater through an outlet 18. The feedwater is recycled back to the power boiler.
Within the typical feedwater heater shown in FIG. 1, there are provided a plurality of heat exchange tubes 20, through which the feedwater flows within shell 12, surrounded by the steam provided through inlet 14. The steam condensate, hereinafter designated as the drains, occurring in the heater is discharged through outlet 22. A detail of the feedwater heater of FIG. 1 is shown in FIG. 2. As illustrated therein, there is provided a subcooler 24 which cools steam condensate 26 to still a lower temperature than attained in the condensing stage, wherein most of the steam's heat is removed as latent heat and wherein gas/liquid equilibrium is essentially obtained. The subcooler 24 thus recovers additional sensible heat from the shell condensate and exchanges the same with the feedwater passing through a path 28 adjacent thereto. The condensate, after further cooling in subcooler 24, exits through drains outlet 22. A valve 30 is provided in the outlet 22, and a level controller 32 is used to control the opening of valve 30 in order to maintain the condensate 26 at a predetermined level within the shell.
In the prior art, the setpoint for level controller 32 is typically set to be at a fixed distance below the bottom dead center of the bottom heat exchange tubes. In one modification provided in the prior art, the liquid level within the shell is determined as follows.
According to this prior art method, the drains subcooler approach, sometimes also referred to as the drains cooler approach and hereinafter identified by the abbreviation DCA, which is the temperature difference between the drains exiting through outlet 22 and the feedwater entering at inlet 16, is measured and plotted as a function of shell liquid level, i.e. the level of steam condensate 26 within shell 12. This data is typically obtained at rated, i.e. maximum, load for the turbine generator operating with steam produced from the heated feedwater provided from the heater 10 (and from other heaters in a typical and known heating train arrangement). A plot of DCA data so obtained is shown at 34 in FIG. 3.
As seen therein, the lower the liquid level the higher the DCA. The relationship between DCA and liquid level, however, exhibits a breakpoint 36. Below the breakpoint the DCA increases significantly. It is known in the art that operation of the feedwater heater at liquid levels below the knee of the curve 34 is inadequate and may result in damage to the heater. Particularly, for liquid levels lower than the level at breakpoint 36, a runaway situation may occur, as follows.
For example, vapor generation may occur at the inlet to subcooler 24. As a result, two phases (liquid and vapor) exist in subcooler 24, resulting in a drop in pressure and in an increase in flow velocity. The increased velocity of the liquid passing through the valves and the cooler creates still a further pressure drop within the cooler, resulting in less efficient heat transfer therein. With less efficient heat transfer, there may occur additional vaporization within the subcooler 24, increasing the flow velocity, further reducing the pressure, etc. Under such conditions, the velocities may increase to destructive levels.
The increased flow velocity, reduced water level and decreased pressure resulting from two-phase conditions within subcooler 24 may erode, knock and vibrate the various heat exchange tubes therein, as well as various end plates, baffles, drains valves and downstream plumbing, resulting in costly (and sometimes irreparable) damage. It is noted that replacement of a large feedwater heater may require expenditures of approximately $500,000.00. Further, since the pressure drop across a valve is related to the square of the fluid velocity therethrough, the above noted increase in velocity may result in conditions where the capacity of the drains valves is exceeded, thus requiring operation of emergency dump valves in order to restore the liquid level within the shell to an acceptable value. It has accordingly been suggested in the prior art to operate with the setpoint adjustment fixed such that the actual liquid level is approximately 1.5 to 2 inches higher than the breakpoint of the DCA characteristic at the boiler load conditions at which the characteristic is obtained, thus providing a margin of safety for varying load conditions.
In the prior art, an extended time period may be required to obtain the curve 34 in FIG. 3, during which an operator manually raises the liquid level to at least 3 inches above the elevation of the bottom most heat exchange tubes. After stabilization of temperatures, performance data is read and the drains approach plotted by dropping the liquid level 1/2 inch at a time, awaiting stabilization, obtaining the DCA data, and repeating the procedure.
However, such an approach is both highly time consumptive of manual labor and, moreover, is inexact. For example, it may typically require a 10 to 15 minute delay between reading of data points to permit stabilization to occur between successive changes in liquid level. Moreover, upon obtaining the DCA curve of FIG. 3, a sight glass or, untypically, other liquid level indicator is required to be monitored to identify the appropriate liquid level (including the margin above the breakpoint). However, because actual levels typically vary and oscillate due to a multiplicity of error factors, it is difficult to obtain accurate DCA curves by using actual sighted levels. Moreover, it is known that sight glass readings are not sufficiently reliable to obtain precise data.
Still a further disadvantage of the prior art results from the practice of obtaining a DCA curve for a single boiler load, typically the rated load of the boiler. When load requirements vary, the DCA characteristics vary as well. Most heaters can be safely operated at decreased liquid level setpoints at lower loads where operation is more efficient. However, because of the prior art difficulty in obtaining the DCA characteristics, only a single such characteristic is obtained and a liquid level control setpoint is typically established such that the liquid level is at a fixed value, typically 1.5 to 2 inches above the breakpoint for maximum rated load, as previously described. Thus, when lower load requirements are imposed on the boiler, operational efficiency is poorer than necessary because the liquid level setpoint is fixed at its predetermined value and is higher than is necessary, providing an excessive margin of safety and resulting in less efficient operation.
By providing an excessive safety factor, i.e. a higher liquid level than necessary, the terminal temperature difference (the difference between saturation temperature corresponding to the entering extraction stream and the outlet feedwater temperature) may experience variations equivalent to loss in heated feedwater temperatures on the order of tenths of a degree. Thus, at low loads, where such an excessive safety factor is likely to occur, the temperature loss resulting from the combined effects of an entire train of feedwater heaters may be as much as a few degrees. Although the temperature differences may appear small, the same may be reflected in losses of more than a billion BTU of energy per year, in waste of a million pounds of coal per year or more, in discharge of thousands of pounds of sulfur oxides into the environment each year, and in added operating expenses of many thousands of dollars per year for a single large power generating boiler (e.g. 500 MW).
There is accordingly a need in the prior art to minimize excesses in safety margin of liquid levels in feedwater heaters.
It is particularly necessary to simplify the manner in which DCA characteristics are obtained in order to permit more load-responsive adjustment of liquid level for shell condensate in feedwater heaters.
Still more particularly, there is a need to reduce the amount of manual intervention required to obtain such DCA characteristics.
There is, in other words, a significant need in the prior art to provide more efficient operation of feedwater heaters by setting the liquid level to the lowest permissible nondestructive levels.
Still a further deficiency in the prior art is the inability appropriately to moderate the liquid level in accordance with variations in load in order to enhance operation of feedwater heaters.
Because of the above described unmet needs, the prior art generally fails to optimize operation of feedwater heaters.